Seismic imaging using omni-azimuth seismic energy sources and directional sensing

ABSTRACT

A method and apparatus for surveying a three dimensional sub-surface geological structure having seismic scatterers includes establishing an acquisition system ( 19 ) having at least two substantially vertical arrays of sensors ( 20 ) disposed within the geological structure. Each array ( 20 ) includes multiple directional sensing receivers  30  adapted to receive seismic energy ( 28, 97 ) produced from the seismic scatterers ( 24 ) in response to at least one seismic disturbance ( 27 ). The multiple directional sensing receivers ( 30 ) are adapted to provide a measurement of the received seismic energy. A recorder records the measurements of the received seismic energy for producing a complete vector field response of the seismic scatterers to the at least one seismic disturbance. Lastly, a processor processes the complete vector field to generate a three-dimensional image.

[0001] This application is a continuation-in-part of copendingapplication U.S. Ser. No. 09/363,584, filed Jul. 29, 1999, entitled“Seismic Imaging Using Omni-Azimuth Seismic Energy Sources andDirectional Sensing, which is a continuation of Ser. No. 08/950,726,filed Oct. 15, 1997, entitled “Seismic Imaging Using Omni-AzimuthSeismic Energy Sources and Directional Sensing, now U.S. Pat. No.6,023,657.

BACKGROUND OF THE INVENTION

[0002] This invention relates generally to seismic surveying, and moreparticularly to three dimensional imaging based upon the use ofomni-azimuth seismic energy sources and directional sensing of seismicscatterers.

[0003] To investigate a salt dome or like configuration, both a seismicsource and seismic receivers or detectors, such as hydrophones, threecomponent geophones, or three component accelerometers, are suspended ina single borehole. Then, seismic signals are sent from the suspendedsource, such as an airgun, and received by the receivers to define amore accurate map of the salt dome's flank configuration than possiblewith surface-located seismic sources and detectors.

[0004] Presently, three-dimensional (3-D) seismic surveys are based uponrecording a vertical component of seismic motion reflected fromsub-surface seismic reflectors. The 3-D surveys rely on the measurementsof travel time from source to reflector, to receiver, and the geometryof source-receiver positions on the surface. This technique requires aneven distribution of seismic energy sources and receivers over theentire surface of the geological field. The seismic data is acquiredseparately at each receiver and it is processed by corrected summing tocreate an image of the sub-surface.

[0005] What is needed is an apparatus and a method for conducting 3-Dseismic surveys using directional sensing rotation within a geologicalstructure's complete vector field that is produced by seismic energyemanating from seismic scatterers in the sub-surface of the geologicalstructure, thereby significantly reducing the need for distribution ofseismic energy sources and receivers over the entire surface of thegeological structure.

SUMMARY OF THE INVENTION

[0006] The present invention, accordingly, provides an apparatus and amethod for conducting 3-D seismic surveys using directional sensingrotation within a geological structure's complete vector field. Seismicenergy emanating from seismic scatterers in the sub-surface of thegeological structure produces sufficient energy for the seismic survey.This technique significantly reduces the need for distribution ofseismic energy sources and receivers over the entire surface of thegeological structure. To this end, according to one embodiment, anapparatus for providing a three-dimensional seismic image includes anomni-azimuthal source of seismic energy positioned adjacent to a surfaceof a geological structure. The source emits a signal of sufficientenergy and bandwidth to produce seismic energy from a seismic scattererin the geological structure. A plurality of arrays of sensors are alsoprovided. Each array has directional sensing receivers aligned in thegeological structure for receiving and recording measurement ofdiffracted seismic energy, to produce a complete vector field. Thecomplete vector field is processed to generate the three-dimensionalseismic image.

[0007] A principal advantage of the present invention is that thesub-surface geological strata is energized (“illuminated”) by a seismicenergy source. The energization causes elastic discontinuities (“seismicscatterers”) to diffract the seismic energy as if they were the sourceof such seismic energy. The receivers measure all diffractions. Arecording unit records all measured diffractions. A processing systemprocesses the recorded information to locate the seismic scatterers,thus creating a three-dimensional image of the sub-surface, which imagecan be interpreted for geological significance.

BRIEF DESCRIPTION OF THE DRAWINGS

[0008]FIG. 1 illustrates a geological structure with a sub-surfaceseismic scatterer.

[0009]FIG. 2 illustrates a directional sensing vertical array withtriphones.

[0010]FIG. 3 illustrates a portion of the directional sensing verticalarray of FIG. 2 in greater detail.

[0011]FIG. 4 illustrates a vectorial rotation of the array of FIG. 2,for calibration.

[0012]FIG. 5 illustrates uphole summing using one vertical array along awavefront at a right angle to the vertical.

[0013]FIG. 6 illustrates a portion of the directional sensing verticalarray of FIG. 5 in greater detail.

[0014]FIG. 7 illustrates uphole summing using one vertical array along awavefront emerging at an angle φ to the vertical.

[0015]FIG. 8 illustrates a portion of the directional sensing verticalarray of FIG. 7 in greater detail.

[0016]FIG. 9 illustrates the preferred embodiment of the presentinvention, which uses uphole summing in conjunction with sensingrotation between three vertical arrays along a unique wavefront.

[0017]FIG. 10 illustrates bending of a monofrequency wavepath.

[0018]FIG. 11 illustrates the range and resolution power of the verticalarray shown in FIG. 1.

[0019]FIG. 12 is an aerial view of a field with omni-azimuthal sourcesand directional sensing vertical arrays.

[0020]FIG. 13 is a flowchart illustrating the process of establishing aplurality of arrays in a geological structure to measure the response ofseismic scatterers to seismic disturbances.

[0021]FIG. 14 is a flowchart illustrating the process of sensingrotation and uphole summing to produce a three dimensional seismicimage.

[0022]FIG. 15 illustrates triangulation techniques utilizing twodirectional sensing vertical arrays.

[0023]FIG. 16 is a flowchart illustrating the process of sensingrotation and triangulation using secondary arrival measurements.

DETAILED DESCRIPTION OF THE INVENTION

[0024] Referring to FIG. 1, within a geological structure 18, anacquisition system 19 includes a plurality of directional sensingvertical arrays (DSVA), each designated 20, an omni-azimuthal (i.e. noazimuthal variation) seismic source (OSS) 22 and a seismic scatterer 24.The seismic scatterer 24 is an elastic discontinuity which whenenergized by a passing seismic wave, acts as a new and independentsource of seismic energy. The geological structure 18 is part of ageological field. Although FIG. 1 illustrates only one scatterer 24, thegeological structure 18 has multiple seismic scatterers 24. Each DSVA 20is located at a near-surface distance, typically within 500 feet of asurface of the geological structure 18. The OSS 22 is located on thesurface or within the near-surface of the geological structure 18 in ahorizontal or vertical arrangement. The OSS 22 has single or multipleelements, having sufficient energy, bandwidth, and beam-angle toadequately energize exploration objectives, such as the geologicalstructure 18. The OSS 22 is either an impulsive source (such asexplosives, impactors, and the like), a coherent vibratory source, or arandom vibratory source. The OSS 22 is designed to produce seismicenergy that is repeatable in order to overcome random ambient noiseinterferences, as discussed below. The OSS 22 emits a seismic energy 27at a beginning time. The seismic energy 27 is omni-azimuthal, withsufficient energy and bandwidth to energize geological objectives, suchas the geological structure 18. The seismic energy 27 has a signaturethat is repeatable for a full spectrum of frequencies.

[0025] As seismic energy 27 travels through the geological structure 18,it energizes the seismic scatterer 24 and all other seismic scatterers(not shown), located within the geological structure 18. Once energized,the seismic scatterer 24 acts as an independent source of seismic energyand produces a diffracted seismic energy 28, i.e. a seismic energyradiated by an elastic discontinuity that has been energized by aseismic disturbance. The seismic scatterer 24 emits the diffractedseismic energy 28 in all directions. The diffracted seismic energy 28travels back to each DSVA 20, which measures the diffracted seismicenergy 28 as a first arrival measurement for the seismic scatterer 24. Arecording unit (not shown) is coupled to each DSVA 20 to record themeasured energies. As the diffracted seismic energy 28 travels back toeach DSVA 20, the diffracted seismic energy 28, acting as an independentsource of seismic energy, energizes secondary seismic scatterers (notshown) surrounding the seismic scatterer 24. The energized secondaryseismic scatterers produce secondary diffracted seismic energies thattravel back to each DSVA 20. Each DSVA 20 measures and the recordingunit records, in addition to the first arrival measurements, secondarydiffracted seismic energies produced by the secondary seismicscatterers. Therefore, each DSVA 20 measures a complete vector field.The complete vector field is used to produce a directional measurementand resolution of the geological structure 18 to accurately locate allseismic scatterers 24.

[0026] Referring now to FIG. 2 and FIG. 3, the DSVA 20 includes aplurality of triphones, each designated 30. A triphone is athree-component geophone with identical orthogonal elements, each makingan angle of 54 degrees, 35 minutes with the vertical (also called aGal'perin geophone), which are commercially available from Input/Output,Inc., having a place of business at 11104 West Airport Blvd., Stafford,Tex. 77477-2416, as part number CA 2729. The length of the DSVA 20equals a longest wavelength component, which is to be measured andrecorded, of the diffracted seismic energies produced by the seismicscatterers 24. Increasing the length of the DSVA 20 improves itsresolution power. Additionally, a spacing interval 29 separates eachtriphone 30 from adjacent triphones 30. The user selects the interval 29to equal half of the shortest wavelength component to be measured andrecorded. Shortening the interval 29 enhances resolution of the DSVA 20.The longest and shortest wavelength components are calculated using acompressional-wave (p-wave) velocity of the geological structure 18surrounding the DSVA 20. The p-wave velocity is a function of thevelocity field. If the p-wave velocity is 1500 meters per second, andthe desired measurement bandwidth is 10 through 100 Hz, then the DSVA 20would have twenty of the triphones 30. The interval 29 between adjacenttriphones 30 would be 7.5 meters. Thus, the length of the DSVA 20 wouldbe 150 meters.

[0027] The user secures each DSVA 20 in position within a borehole usinga material of equal or slightly lesser propagation velocity than theformation, which is part of the geological structure 18, surrounding theborehole. The user secures each DSVA 20 in a different borehole. Theuser surveys each borehole containing the DSVA 20 to determine theborehole's precise coordinates and inclination, to calibrate each DSVA20. The user calibrates each DSVA 20 using XYZ coordinates, orientation,and interconnecting travel times for each triphone 30 of each DSVA 20with respect to other triphones 30 in all the other DSVAs 20.

[0028] Referring now to FIG. 4, XYZ coordinates 31 are defined byloading each DSVA 20 into the borehole in such a manner that the usermeasures and records the exact depth of each triphone 30 of each DSVA20. The user orients each DSVA 20 to a C axis, true North axis 33, usingvectorial rotation of data for each triphone 30 in relation to amulti-element up-hole calibration source of known coordinates,conveniently located in the vicinity of each DSVA 20. The userdetermines the vectorial rotation according to the following equations:$\begin{matrix}{\underset{\sim}{A} = {{\cos \quad {\delta \begin{pmatrix}1 & 0 & 0 \\0 & 1 & 0 \\0 & 0 & 1\end{pmatrix}}} + {\left( {1 - {\cos \quad \delta}} \right){x\begin{pmatrix}c_{1}^{2} & {c_{1}c_{2}} & {c_{1}c_{3}} \\{c_{2}c_{1}} & c_{2}^{2} & {c_{2}c_{3}} \\{c_{3}c_{1}} & {c_{3}c_{2}} & c_{3}^{2}\end{pmatrix}}} + {\sin \quad {\delta \begin{pmatrix}0 & {- c_{3}} & c_{2} \\c_{3} & 0 & {- c_{1}} \\{- c_{2}} & c_{1} & 0\end{pmatrix}}}}} & {{equation}\quad 1(c)} \\{\begin{pmatrix}X \\Y \\Z\end{pmatrix} = {\underset{\sim}{A}\begin{pmatrix}X^{\prime} \\Y^{\prime} \\Z^{\prime}\end{pmatrix}}} & {{equation}\quad 1(d)}\end{matrix}$

[0029] where δ is a rotation angle, a is an observed vector, c is anaxis of rotation, and e is an emergence vector. From the elements of theup-hole calibration source, the user obtains interconnecting traveltimes to each triphone 30. The user determines differential travel timesbased on the relationship between the position of the OSS 22 and depthof each triphone 30. Using the differential travel times, the usergenerates a velocity field for an area of the geological structure 18surrounding each DSVA 20. Later, the user uses the velocity field toadjust the diffracted seismic energies 28 along wavefronts travelingthrough the area of the geological structure 18 surrounding each DSVA20.

[0030] The user selects a layout and a position for each DSVA 20 and theOSS 22 depending on the nature and extent of the exploration objectives.Once the user selects the layout and the position, acquisition of fielddata can commence. The acquisition involves recording the completevector field. The OSS 22 generates the seismic energy 27 as illustratedin FIG. 1. Each of the DSVAs 20 measures the diffracted seismic energy28 for each of the seismic scatterers 24. The recorded informationrelating to the seismic energy 27 has a real component and an imaginarycomponent, together called a complex trace. The complex trace hasattributes that includes information about instantaneous phase,reflection strength representing the envelop of a given wavelet,instantaneous bandwidth, instantaneous polarity, and instantaneousfrequency, along with other properties that can be calculated for thecomplete vector field.

[0031] Ambient noises produced during the recording of the completevector field must be sufficiently attenuated. Ambient noises are randomwhile the seismic energy 27 is repeatable. Accordingly, the diffractedseismic energy 28 is also repeatable. In order to sufficiently attenuateambient noises, the OSS 22 repeats the seismic energy 27 to recordsuccessive complete vector fields and hence successive complex traceattributes. Successive seismic energies 27 are produced until thecomplex trace attributes of two successive complete vector fieldsindicate that ambient noises are sufficiently attenuated. For example, azero instantaneous phase differential of the complex trace attributes oftwo successive complete vector fields indicates that ambient noises havebeen sufficiently attenuated.

[0032] The complete vector field comprises multiple signals receivedfrom multiple directions, with ambient noises sufficiently attenuated.Each triphone 30 measures the diffracted seismic energy 28 from anygiven direction. Thus, each DSVA 20 can precisely locate the seismicscatterer 24 using a combination of uphole summing, as discussed below,and sensing rotation. Sensing rotation is used because each directionalmeasurement is represented by a three-component orthogonal signal. Thethree-component orthogonal signal is referenced to the azimuth of thetrue North axis 33, and also referenced to a declination from thehorizontal using the vectorial rotation calibration data established byequations 1(a) through 1(d). The vectorial rotation involves summing thethree-component orthogonal signal in such manner that the resultingsignal corresponds to the one that would have been received from thedirection of the seismic scatterer 24. This is done by summing thethree-component orthogonal signal in proportion to the sphericalcoordinate transform that corresponds to the azimuth and inclination inthe direction of the seismic scatterer 24. The process is represented bythe equation: $\begin{matrix}{\rho = \frac{\frac{X}{\sin \quad \varphi \quad \cos \quad \theta} + \frac{Y}{\sin \quad \varphi \quad \sin \quad \theta} + \frac{Z}{\cos \quad \varphi}}{3}} & {{equation}\quad (2)}\end{matrix}$

[0033] where ρ is the scalar value of the sum, θ is the azimuth, φ isthe inclination, X is an x-component of the three-component orthogonalsignal, Y is a y-component of the three-component orthogonal signal, andZ is a z-component of the three-component orthogonal signal. Thus, thetriphone 30 can be focused in any given direction using vectorialrotation, without physical rotation of the triphone 30.

[0034] Referring now to FIG. 5 and FIG. 6, triphones 30 a, 30 b and 30^(n) are part of each DSVA 20. A processing system (not shown) performsuphole summing by taking the diffracted seismic energy 28 received atthe triphone 30 a, the deepest triphone of the DSVA 20, and summing itto the diffracted seismic energy 28 received at the triphone 30 b, whichis immediately above the triphone 30 a, with an uphole time delaydesignated ΔT. The processing system repeats the summing process up to,and including, the diffracted seismic energy 28 received at theuppermost triphone 30 ^(n). Summing with the delay ΔT along a verticalaxis 34 of the DSVA 20 enhances an emerging wavefront 35 at zero degreesfrom the vertical axis 34.

[0035] Referring now to FIG. 7 and FIG. 8, an emerging wavefront 36travels along an axis 38, at an angle φ to the vertical axis 34. Upholesumming with an angle uphole delay ΔT*cos φ, along the angle axis 38,enhances the emerging wavefront 36 traveling at the angle φ. Summingwith the angle uphole delay ΔT*cos φ, and sensing rotation of thetriphones 30 a through 30 ^(n) to any given azimuth and declination,allows the DSVA 20 to focus in a desired direction to isolate thediffracted seismic energies 28 received from the desired direction.Therefore, the DSVA 20 is made highly directional to precisely locatethe seismic scatterer 24, using sensing rotation in conjunction withuphole summing.

[0036] Referring now to FIG. 9, in the preferred embodiment of thepresent invention, a DSVA 20 a, a DSVA 20 b, and a DSVA 20 c record anemerging wavefront 54, i.e. a wavefront orthogonal to a diffractiondirection propagating away from a given seismic scatterer. The DSVA 20a, the DSVA 20 b, and the DSVA 20 c are shown with identical azimuthsand vertical inclinations. Thus, vision lines of the DSVA 20 a, the DSVA20 b, and the DSVA 20 c are parallel and in unison with proper rotation.As the emerging wavefront 54 cuts across the DSVA 20 a, the DSVA 20 b,and the DSVA 20 c along an emerging azimuth and an emerging declination,the processing system performs uphole summing using correspondingtriphones and uphole delays. Uphole summing for the DSVA 20 a occurssimultaneously to uphole summing for the DSVA 20 b and the DSVA 20 c.The processing system uses uphole delays calculated for the emergingazimuth and the emerging declination, based on velocities of thevelocity field obtained during the calibration process. Thus, bycombining the uphole summing for the DSVA 20 a with the DSVA 20 b andthe DSVA 20 c, the processing system enhances information recorded fromthe emerging azimuth and the emerging declination while attenuatingsignals from the other directions. For example, a triphone 56, atriphone 58, and a triphone 60 of the DSVA 20 a, the DSVA 20 b, and theDSVA 20 c, respectively receive the wavefront 54. Thus, summing therecorded measurements of the triphones 56, 58, and 60 is the same asuphole summing along one path of the emerging wavefront 54 at an instantin time. At another instant in time, the wavefront 54 reaches a triphone62, a triphone 64, and a triphone 66. Eventually, the wavefront 54 willpropagate through the geological structure 18 to reach a triphone 68, atriphone 70, and a triphone 72. Therefore, starting at the triphone 62,and stopping when summing has reached the triphone 68, a total offifteen intervals are summed to enhance the diffracted seismic energyassociated with the wavefront 54.

[0037] Referring now to FIG. 10, monofrequency wave 73 travels along amonofrequency wavepath 74. Monofrequency decomposition of the diffractedseismic energy 28 from the seismic scatterer 24 yields a plurality ofFresnel rings (i.e. a monofrequency response of the diffracted seismicenergy from the seismic scatterer) of a certain shape, size, anddistribution as measured by the multiple DSVA 20 of FIG. 9. Each Fresnelring has a first Fresnel zone 75, i.e. the portion of a scatterer fromwhich diffracted energy can reach a detector within one-half wavelengthof the first diffracted energy. In general, smaller Fresnel ringscorrespond to higher frequency components and larger Fresnel rings tolower frequency components. For a given angle of incidence of themonofrequency event, the angle of refraction varies as a function of thewavelength, and thus velocity. Furthermore, variations in the angle ofrefraction cause bending in wavepaths. Wavepaths differ according to thevelocities and time-distance between the seismic scatterer 24 and eachDSVA 20. Thus, a velocity function can be derived from analyses of theFresnel rings as a function of time-distance. The velocity function actsas a velocity model, which comes from the monofrequency decomposition ofthe Fresnel rings. Accordingly, the velocity function is used to correctthe bending and hence accurately locate the position of the seismicscatterer 24.

[0038] Referring now to FIG. 11, the DSVA 20 has a top triphone 76, abottom triphone 78, a range D, a scanning resolution d, an angularsampling rate 84, and a vision angle φ. The DSVA 20 has a total verticaldelay T and a temporal sample rate Δt. The angular sample rate 84 isdefined by the equation: $\begin{matrix}{{\Delta \quad \varphi} = {{\cos^{- 1}\left( \frac{{T\quad \cos \quad \Phi} - {\Delta \quad t}}{T} \right)} - \Phi}} & {{equation}\quad (3)}\end{matrix}$

[0039] From equation (3), the scanning resolution d of the DSVA 20 canbe determined and expressed by the following equation:

d=D tan Δφ  equation (4)

[0040] In FIG. 12 a geological field 90 is illustrated with multipleDSVAs 20 and multiple OSSs 22 for large field exploration. In additionto the features noted above, layout of the field 90 allows collectionand correction of near-horizontal data. A path traveled along anear-horizontal plane suffers from bending. If bending occurs, theseismic scatterer appears to be deeper than the seismic scatterer's trueposition, because velocity generally increases with depth. Thus,near-horizontal data relating to the location of a seismic scatterer 92shows the seismic scatterer 92 located deeper than its true position.Consequently, the user corrects for bending in the near-horizontal databy warping the velocity field using near-vertical data. Bending of theline of vision is minimum in a vertical direction. Thus, seismicscatterers are located in near true position when using near-verticaldata. Accordingly, the near-vertical data relating to the location ofthe seismic scatterer 92 is the most accurate measurement due to minimumvelocity variations with depth in the vertical direction. Thus, the userdetermines a true position of the seismic scatterer 92 using thenear-vertical data measured by a DSVA 94 located substantially above theseismic scatterer 92.

[0041] The user compares the true position to a secondary position ofthe seismic scatterer 92 determined using the near-horizontal datameasured by a DSVA 96 located some distance away from the seismicscatterer 92. By comparing, the user determines an error and acorrection factor needed to correct the near-horizontal data. The usercorrects the near-horizontal data by adjusting to near-vertical data onadjacent and overlapping coverage in the geological field using thecorrection factor. The correction involves warping a seismic image inspace. The amount and distribution of the warping is related to avelocity field causing the bending or distortion. In addition to thewarping, a non-zero offset source (not shown) positioning can addvaluable information for recording shallow data and defining thevelocity field with greater precision.

[0042] Referring now to FIG. 13, the user begins in step 101. In step102, the user establishes an acquisition system. Then in step 104, theuser triggers the OSS 22 to energize the seismic scatterers 24. In step106, the recording unit records the response of the seismic scatterers24 to the seismic energy 27. In step 108, the user correctsnear-horizontal data.

[0043] In order for the user to establish the acquisition system in step102, in step 112, the user selects the spacing interval between each ofthe triphones 30. In step 114, the user also selects the length of eachDSVA 20. In step 116, the user secures the DSVA 20 in the borehole. Instep 118, the user aligns the axis of the DSVA 20 to other DSVAs 20, sothat all of the axes are parallel. In step 120, as the user places eachDSVA 20 into the borehole, the user determines the depth of eachtriphone. In step 122, the user fires calibration shots in the vicinityof each DSVA 20. In step 124, the processing system establishes a timedelay based on the response of each DSVA 20 to the calibration shot. Instep 126, the processing system cross-calibrates the DSVAs 20.

[0044] In step 132, the user selects the OSS 22. In step 134, the userplaces the OSS 22 at or near the surface of the geological structure 18.In step 136, the user triggers the OSS 22 and the recording unit recordsthe response. In step 138, the user determines whether ambient noisesare sufficiently attenuated. If ambient noises are not sufficientlyattenuated, then execution returns to step 136 and the user triggers theOSS 22 again. If ambient noises are sufficiently attenuated then therecording unit has recorded the complete vector field in the step 106.

[0045] Referring now to FIG. 14 in step 144, the processing systemsenses rotation. In step 146, the processing system generates componentsof the measured values in a sensing direction. Depending on the type ofprocessing desired, the processing system performs step 148, step 150,or both sequentially. It is noted that the processing system can performstep 148 and step 150 in any order. In step 148, the processing systemuses uphole summing to enhance the resolution of the three dimensionalimage in the sensing direction. In step 150, the processing system usesuphole summing along a wavefront to enhance sensing along the wavefront.In step 152, the processing system determines whether a threedimensional image has been generated. If more directions must beconsidered, then in step 154, the processing system selects a newdirection, and execution returns to step 144.

[0046] In step 158, the processing system selects a recorded measurementof the triphone 30 a, (FIG. 5), the bottom sensor, and in step 160,performs uphole summing. In step 162, the processing system selects therecorded measurement of the next highest triphone, and, in step 164,checks to see if the triphone is the highest triphone. If the nexthighest triphone is not the triphone 30 ^(n), then the processing systemreturns to the step 160 to perform uphole summing. If the next highesttriphone is the triphone 30 ^(n), then the processing system goes tostep 150 if summing along the wavefront is required. If uphole summingis not required then the processing system goes to step 152 to determineis a three dimensional seismic image is generated.

[0047] To sum along the wavefront in step 150, in step 170, theprocessing system selects a starting time. In step 172, the processingsystem sums along the wavefront corresponding to a path of thewavefront. In step 174, the processing system determines if the timeselected corresponds to a time when the wavefront reaches the toptriphone of at least one of the DSVAs 20, which lies in the path of thewavefront. If the top triphone is not reached, then in step 176, anothertime is selected, and execution returns to step 172. Otherwise,execution returns to step 152, and continues until a three dimensionalseismic image is generated, and execution ends at step 190.

[0048] Referring now to FIG. 15, in an alternate embodiment of thepresent invention, the processing system uses a secondary diffractedseismic energy 97 to locate a secondary seismic scatterer 24 a. Thediffracted seismic energy 28 re-energizes the secondary seismicscatterer 24 a, which occurs a predetermined time period after theinitial energization caused by the seismic energy 27. Re-energizationcontinues for some time resulting in multiple energizations (not shown).Accordingly, multiple energizations will occur from multiple directionsafter the predetermined time period has lapsed. Each DSVA 20 measuresthe multiple energizations as secondary arrival measurements, after thefirst arrival measurements.

[0049] After the recording unit records the secondary arrivalmeasurements, the processing system locates the seismic scatterers usingdirectional sensing in conjunction with triangulation techniques. Theprocessing system performs triangulation by comparing the secondaryarrival measurements measured by at least two selected clusters of DSVAs98 and 99 separated by a predetermined separation distance S. Theseparation distance S is preferably in the range of one-half mile up tothree miles. Initially the vision lines of each cluster of DSVAs 98 and99 are parallel to one another. Triangulation is achieved by focusingthe vision lines of the cluster of DSVAs 98 and 99, using sensingrotation, so that the vision lines of each cluster moves from theparallel position toward each other, in search of coherency in thecomplete vector field. The coherency is determined by using some form ofa pattern recognition process. Once the coherency is located, then theapparent position of the seismic scatterer 24 a, which produced thecoherency measured by cluster of DSVAs 98 and 99, can be accuratelydetermined independent of time and velocity.

[0050] Referring now to FIG. 16, a flowchart 200 illustrates the processfor sensing rotation combined with triangulation using at least twoDSVAs 20, which process begins at step 201. In step 210, the userseparates the DSVAs 20 by the separation distance S, FIG. 15. In step220, the user triggers the OSS 22 to energize the seismic scatterers 24to produce diffracted seismic energy. The diffracted seismic energyre-energizes the seismic scatterer 24 a. The re-energized seismicscatterer 24 a produces the secondary diffracted seismic energy 97. Instep 240, the recording unit records the secondary diffracted seismicenergy 97 as the secondary arrival measurement, along with the firstarrival measurements. In step 260, the processing system focuses in adirection of a coherency. In step 280, the processing system calculatesthe apparent position of the seismic scatterer 24 a. In step 290, theuser corrects near-horizontal data. The user repeats the process setforth in the flowchart 200 until all desired apparent positions ofseismic scatterers are determined, and then ends execution in step 300.

[0051] In another embodiment of the present invention, a non-repeatablerandom energy source (NRES) replaces the OSS 22. The user monitors theoutput of the NRES and records a reliable measurement of theomni-azimuth signature for later correlation.

[0052] In yet another embodiment of the present invention the DSVA isreplaced by a directional sensing array (DSA) that is substantiallyvertical. The DSA can deviate up to twenty degrees from the vertical.

[0053] In operation, the OSS 22 emits a seismic energy 27 into ageological field. The seismic energy 27 energizes seismic scatterers 24in the geological field. The energized seismic scatterers 24 act asindependent sources of seismic energy and emit diffracted seismicenergies 28. Each DSVA 20 measures the diffracted seismic energies 28 asfirst arrival measurements. As the diffracted seismic energies 28 travelthrough the geological structure 18, the diffracted seismic energies 28re-energize other seismic scatterers 24 to produce secondary diffractedseismic energies 97. Each DSVA 20 measures the secondary diffractedseismic energies 97 as secondary arrival measurements. Thus, each DSVA20 measures a complete vector field. The triphones 30 of the DSVA 20 canbe focused in a desired direction using sensing rotation within thecomplete vector field. Sensing rotation is combined with uphole summingto precisely locate the seismic scatterers 24 in the three dimensionalimage using time-distance relations of the first arrival measurements.Alternatively, sensing rotation is combined with triangulationtechniques to locate the apparent position of the seismic scatterers 24independent of time, using secondary arrival measurements. On the otherhand, sensing rotation and uphole summing can be combined with sensingrotation and triangulation techniques to create the three dimensionalseismic image.

[0054] According to another embodiment of the present disclosure, anapparatus for providing a three-dimensional seismic image includes anomni-azimuthal source, at least two substantially vertical arrays ofsensors, a recorder, and a processor. The omni-azimuthal source ofseismic energy is positioned proximate a surface of a geologicalstructure. In response to an activation, the omni-azimuthal source ofseismic energy emits a signal of sufficient energy and bandwidth toproduce seismic energy from a seismic scatterer in the geologicalstructure. Each array of the at least two substantially vertical arraysof sensors includes multiple directional sensing receivers substantiallyvertically aligned in the geological structure. The multiple directionalsensing receivers receive seismic energy produced from seismicscatterers and are adapted to provide a measurement of the receivedseismic energy.

[0055] The recorder can include any suitable recorder known in the art.The recorder records the measurement of the seismic energy received bythe at least two substantially vertical arrays of sensors in response toone or more activations of the omni-azimuthal source. The measurement ofseismic energy produces a complete vector field from which to generatethe three-dimensional image. In addition, the recorder can be used torecord an omni-azimuthal signature of a given geological structure. Theomni-azimuthal signature is adapted to correlate seismic energy receivedby the vertical arrays of sensors in response to seismic energy ofinterest, for example, seismic energy produced by seismic scatterers inresponse to non-repeatable random energy sources.

[0056] The processor processes the complete vector field to generate thethree-dimensional image. The processor can include any suitableprocessor, computer, or signal processor. Programming of the processorto perform the various functions as discussed and described herein canbe accomplished using programming techniques well known in the art.

[0057] In addition to processing the complete vector field to generatethe three-dimensional image, the processor furthermore separatesdirectional components from a sum of the scattered seismic energyreceived from scatterers in substantially all directions. For example,separating directional components can include summing signals of thecomplete vector field along a desired direction defined by an azimuthand declination, for producing a single trace data per sensor, perdirection.

[0058] Separating directional components can also include summing singletrace data from sensors of the substantially vertical arrays, in amanner such that elements of the single trace data being summed at anyone time are located on an emerging wavefront of interest. The summingof single trace data on the emerging wavefront of interest is further afunction of summing delays derived from calibrated velocities.Accordingly, a single trace data per sensor array, per direction can beproduced.

[0059] In another embodiment, separating directional components can alsoinclude coherency summing. Coherency summing focuses the substantiallyvertical arrays of sensors on a desired seismic scatterer by patternrecognition. A difference in direction of the desired seismic scatterer,as viewed from the substantially vertical arrays of sensors, is measuredas part of a triangulation process from at least two known locations.Using triangulation, an apparent spatial position of the desired seismicscatter can be established.

[0060] Separating directional components still further includesmeasurement of a dispersion velocity between the desired seismicscatterer and one of the vertical arrays of sensors. Measuring thedispersion velocity can be accomplished via monofrequency decompositionof an apparent size and shape of Fresnel rings. The dispersion velocityis adapted to correct the apparent spatial position of the desiredseismic scatter.

[0061] In yet still another embodiment, the recorder is adapted torecord the measurement of seismic energy of a first complete vectorfield and a second complete vector field. The second complete vectorfield is representative of a time-lapsed first complete vector field..In this embodiment, the processor processes the first and secondcomplete vector fields to identify a difference between the firstcomplete vector field and the second complete vector field. Such adifference is indicative of a change within the geological structure,for example, a physical change in the sub-surface.

[0062] In another embodiment, each of the vertical arrays of sensorsincludes an array length substantially equal to a length of a longestwavelength component of the seismic energy of interest. The sensors ofeach array are spaced at intervals substantially equal to one-half of ashortest wavelength component of the seismic energy of interest. Thelongest and shortest wavelength components of interest are calculated asa function of a desired wave type velocity of the structure surroundingthe array.

[0063] In yet another embodiment, the processor is further forprocessing the complete vector field for detecting and defining a typeof particle motion with respect to a direction of an elastic wavepropagation of seismic energy produced from one or more seismicscatterers within the geological structure. For example, the type ofparticle motion may include longitudinal, vertically transversal andhorizontally transversal waveforms. In another embodiment, the type ofparticle motion may include other than longitudinal, verticallytransversal and horizontally transversal waveforms.

[0064] With respect to the embodiment of the previous paragraph, elasticwave types commonly known in the seismic industry today include surfacewaves and body waves. Surface waves are waves that travel on the surfaceof a geological sub-surface. Surface waves mainly comprise Love andRaleigh waves, commonly referred to as ground roll. Body waves are wavesthat travel within the geological sub-surface. Body waves includelongitudinal, transversal horizontal, and transversal vertical. Bodywaves are of particular interest, whereas, surface waves are of lessparticular interest.

[0065] Longitudinal (Pressure or p-wave) waves include particle motionthat is in the direction of the wave propagation. Transversal horizontal(Shear or SH-wave) waves include particle motion that is horizontallyperpendicular to the direction of the wave propagation. Transversalvertical (Shear or SV-wave) waves include particle motion that isvertically perpendicular to the direction of the wave propagation. Theembodiments of the present disclosure enable detection of the abovetypes of particle motion with respect to the direction of the elasticwave propagation. The embodiments of the present disclosure also enablea detecting and defining of any and all types of particle motion withrespect to the direction of the elastic wave propagation that is beyondthe currently defined longitudinal, vertically transversal andhorizontally transversal waveforms.

[0066] According to yet another embodiment, an apparatus is provided formeasuring a response of sub-surface seismic scatterers in a geologicalstructure to at least one seismic disturbance. The apparatus includestwo or more substantially vertical arrays of sensors, a recorder, and aprocessor. Each array includes multiple directional sensing receiverssubstantially vertically aligned in the geological structure. Themultiple directional sensing receivers are adapted to receive seismicenergy produced from seismic scatterers in response to a seismicdisturbance. The multiple directional sensing receivers further areadapted to provide a measurement of the received seismic energy. In thisembodiment, the recorder records a measurement of the seismic energyreceived by the substantially vertical arrays of sensors, wherein themeasurement of seismic energy produces a complete vector field.Subsequently, the processor generates a three-dimensional image from thecomplete vector field of measured seismic energy.

[0067] The embodiment can also include an omni-azimuthal source ofseismic energy for providing at least one seismic disturbance. In suchan instance, the omni-azimuthal source is positioned proximate a surfaceof the geological structure for providing the seismic disturbance. Uponan activation, the omni-azimuthal source emits a signal of sufficientenergy and bandwidth to produce seismic energy from the seismicscatterers in the geological structure. The recorder records themeasurement of the seismic energy received by the substantially verticalarrays of sensors in response to the activation of the omni-azimuthalsource.

[0068] The at least one seismic disturbance may further include oneproduced from a source other than the omni-azimuthal source. Forexample, the other source might include physical changes in thesub-surface. In such an instance, the recorder records seismic energyreceived by the substantially vertical arrays of sensors from seismicenergy produced by the seismic scatterers in response to the source(other than the omni-azimuthal source). In addition, the recorderfurther records at least one omni-azimuthal signature, wherein theomni-azimuthal signature is adapted for correlation with measurements ofseismic energy produced in response to the other source.

[0069] Accordingly, the embodiments of the present disclosure includepassive monitoring of background seismic radiation emanating fromgeologic objectives. Passive monitoring can be accomplished using thedirectional sensing and processing methodology embodiments of thepresent disclosure. With passive monitoring, seismic energy is generatedas a result of physical changes in the sub-surface.

[0070] Seismic disturbances can be created in the sub-surface by avariety of means. One example would be the result of producinghydrocarbons from a sub-surface reservoir. Fluid flow through areservoir creates micro-fracturing that propagates seismic waves to thesurface. Monitoring of the energy emissions would allow detection offluid fronts, such as oil, water or gas moving through the reservoir.Information obtained via the directional sensing and processingmethodology of the embodiments of the present disclosure can beadvantageously used for optimizing secondary recovery techniques, suchas water or CO₂ injection.

[0071] Another example of seismic disturbance would be the seismicemissions generated from a well bore operation, such as fracturestimulation. In this instance, sand is forced into the reservoir underpressure to create fractures that enhance the ultimate oil and gasrecovery from a given well bore. Using information obtained via thedirectional sensing and processing methodology of the embodiments of thepresent disclosure, imaging of the extent of penetration of the sandinto the reservoir is possible. Accordingly, the imaging informationenables a petroleum engineer to more readily optimize parameters forfuture stimulation operations.

[0072] Accordingly, passive monitoring applications utilize the variousembodiments of the directional sensing vertical arrays, measurementtechniques, and processing techniques as discussed herein. For passivemonitoring, the seismic source (OSS) includes a source resulting from adisturbance in the sub-surface. The seismic scatterer would be at thepoint of the seismic source. The one or more DVSA records over a periodof time, and data is processed accordingly, as discussed herein.Comparison of multiple recordings from different chronological periodsprovides for detection of changes in a reservoir relating to theproduction or stimulation techniques discussed above.

[0073] The principle advantages of the present invention include theability to measure and record a complete vector field; imaging seismicscatterers rather than just locating reflections; measuring directionvectors; requiring only partial surface coverage rather than 100%coverage; uphole summing of the data rather than individually acquiringdata; and directional separation during processing. A geological surveyof a geological structure can be accurately produced and the location ofsub-surface elastic boundaries or seismic scatterers can be preciselydetermined. Less labor is needed, which reduces cost and increasessecurity. Less channels are needed, and fewer source positions arerequired, to produce continuous coverage of the geological structure.Turn-around time for field acquisition data is reduced significantly.Higher resolution and an improved signal-to-noise ratio is achieved.

[0074] Although illustrative embodiments have been shown and described,a wide range of modifications, changes and substitutions is contemplatedin the foregoing disclosure. In some instances, some features of theembodiments may be employed without a corresponding use of otherfeatures. Accordingly, it is appropriate that the appended claims beconstrued broadly and in a manner consistent with the scope of theembodiments disclosed herein.

What is claimed is:
 1. Apparatus for providing a three-dimensionalseismic image comprising: an omni-azimuthal source of seismic energypositioned proximate a surface of a geological structure for emitting asignal of sufficient energy and bandwidth to produce seismic energy froma seismic scatterer in the geological structure; at least twosubstantially vertical arrays of sensors, each array including multipledirectional sensing receivers substantially vertically aligned in thegeological structure for receiving the seismic energy produced from theseismic scatterer and adapted to provide a measurement of the receivedseismic energy; and a recorder for recording the measurement of theseismic energy received by said at least two substantially verticalarrays of sensors in response to at least one activation of saidomni-azimuthal source, the measurement of seismic energy producing acomplete vector field from which to generate the three-dimensionalimage.
 2. The apparatus of claim 1, wherein said recorder furtherrecords an omni-azimuthal signature adapted to correlate seismic energyreceived by said at least two substantially vertical arrays of sensorsin response to a non-repeatable random energy source producing seismicenergy from the seismic scatterer.
 3. The apparatus of claim 1, furthercomprising: a processor for processing the complete vector field togenerate the three-dimensional image.
 4. The apparatus of claim 3,wherein said processor is further for separating directional componentsfrom a sum of the scattered seismic energy received from scatterers insubstantially all directions.
 5. The apparatus of claim 4, whereinseparating directional components includes summing signals of thecomplete vector field along a desired direction defined by an azimuthand declination, for producing a single trace data per sensor, perdirection.
 6. The apparatus of claim 5, wherein separating directionalcomponents further includes summing single trace data from sensors ofsaid at least two substantially vertical arrays, in a manner such thatelements of the single trace data being summed at any one time arelocated on an emerging wavefront of interest as a function of summingdelays derived from calibrated velocities, for producing a single tracedata per sensor array, per direction.
 7. The apparatus of claim 4,wherein separating directional components includes coherency summing,coherency summing adapted to focus the at least two substantiallyvertical arrays of sensors on a desired seismic scatterer by patternrecognition, further wherein a difference in direction of the desiredseismic scatterer as viewed from the at least two substantially verticalarrays of sensors is measured as part of a triangulation process from atleast two known locations, for establishing an apparent spatial positionof the desired seismic scatter.
 8. The apparatus of claim 7, whereinseparating directional components includes measurement of a dispersionvelocity between the desired seismic scatterer and one of said at leasttwo substantially vertical arrays of sensors by monofrequencydecomposition of an apparent size and shape of Fresnel rings, thedispersion velocity adapted to correct the apparent spatial position ofthe desired seismic scatter.
 9. The apparatus of claim 3, wherein saidprocessor is further for separating directional components, from a sumof the scattered seismic energy received from scatterers insubstantially all directions, by summing components along a desireddirection defined by an azimuth and declination, between a distal sensorand a proximate sensor of said at least two substantially verticalarrays of sensors.
 10. The apparatus of claim 3, wherein said processoris further for summing directional components of the recorded signalsfrom successive ones of the sensors of said at least two substantiallyvertical arrays along a wavefront traveling in a desired direction, thedirection defined by an azimuth and declination.
 11. The apparatus ofclaim 3, further wherein said recorder is adapted to record themeasurement of seismic energy of a first complete vector field and asecond complete vector field, the second complete vector fieldrepresentative of a time-lapsed first complete vector field, and whereinsaid processor is further for processing the first and second completevector fields to identify a difference between the first complete vectorfield and the second complete vector field, the difference beingindicative of a change within the geological structure.
 12. Theapparatus of claim 1, wherein said omni-azimuthal seismic energy sourceincludes at least one selected from an impulsive energy source and avibratory energy source.
 13. The apparatus of claim 1, wherein eachdirectional sensing receiver of said at least two substantially verticalarrays of sensors is adapted to receive energy constituting a sum ofscattered seismic energy from scatterers in substantially alldirections.
 14. The apparatus of claim 1, wherein the directionalsensing receivers of said at least two substantially vertical arrays ofsensors include triphones.
 15. The apparatus of claim 14, furthercomprising a material for securing the triphones within the geologicalstructure, the material having a substantially similar velocity as thatof a surrounding structure at the location of a respective triphonewithin the geological structure.
 16. The apparatus of claim 1, whereineach array of said at least two substantantially vertical arrays ofsensors includes an array length substantially equal to a length of alongest wavelength component of the seismic energy of interest, and thesensors of each array are spaced at intervals substantially equal toone-half of a shortest wavelength component of the seismic energy ofinterest.
 17. The apparatus of claim 16, wherein the longest andshortest wavelength components of interest are calculated as a functionof a desired wave type velocity of the structure surrounding the array.18. The apparatus of claim 3, wherein said processor is further forprocessing the complete vector field for detecting and defining a typeof particle motion with respect to a direction of an elastic wavepropagation of seismic energy produced from the seismic scatterer. 19.The apparatus of claim 18, wherein the type of particle motion includeslongitudinal, vertically transversal and horizontally transversalwaveforms.
 20. The apparatus of claim 18, wherein the type of particlemotion includes other than longitudinal, vertically transversal andhorizontally transversal waveforms.
 21. An apparatus for measuring aresponse of a sub-surface seismic scatterer in a geological structure toat least one seismic disturbance, the apparatus comprising: at least twosubstantially vertical arrays of sensors, each array including multipledirectional sensing receivers substantially vertically aligned in thegeological structure, the multiple directional sensing receivers adaptedto receive the seismic energy produced from the seismic scatterer inresponse to the at least one seismic disturbance, the multipledirectional sensing receivers further being adapted to provide ameasurement of the received seismic energy; and a recorder for recordingthe measurement of the seismic energy received by said at least twosubstantially vertical arrays of sensors, the measurement of seismicenergy suitable for use in producing a complete vector field forgeneration of a three-dimensional image.
 22. The apparatus of claim 21,further comprising: an omni-azimuthal source of seismic energypositioned proximate a surface of the geological structure for providingthe at least one seismic disturbance, said omni-azimuthal sourceemitting a signal of sufficient energy and bandwidth to produce seismicenergy from the seismic scatterer in the geological structure, whereinsaid recorder records the measurement of the seismic energy received bysaid at least two substantially vertical arrays of sensors in responseto at least one activation of said omni-azimuthal source.
 23. Theapparatus of claim 22, wherein the at least one seismic disturbancefurther includes one from a source other than said omni-azimuthal sourceof energy.
 24. The apparatus of claim 23, wherein the source other thansaid omni-azimuthal source of energy includes physical changes in thesub-surface.
 25. The apparatus of claim 23, wherein said recorderfurther records at least one omni-azimuthal signature, theomni-azimuthal signature being adapted to correlate seismic energyreceived by said at least two substantially vertical arrays of sensorsfrom seismic energy produced by the seismic scatterer in response to thesource other than said omni-azimuthal source of energy.
 26. Theapparatus of claim 23, further comprising: a processor for processingthe complete vector field to generate the three-dimensional image. 27.The apparatus of claim 26, further wherein said recorder is adapted torecord the measurement of seismic energy of a first complete vectorfield and a second complete vector field, the second complete vectorfield representative of a time-lapsed first complete vector field, andwherein said processor is further for processing the first and secondcomplete vector fields to identify a difference between the firstcomplete vector field and the second complete vector field, thedifference being indicative of a sub-surface change within thegeological structure.
 28. The apparatus of claim 26, wherein saidprocessor is further for separating directional components from a sum ofthe scattered seismic energy received from scatterers in substantiallyall directions. 29 The apparatus of claim 28, wherein separatingdirectional components includes summing signals of the complete vectorfield along a desired direction defined by an azimuth and declination,for producing a single trace data per sensor, per direction.
 30. Theapparatus of claim 29, wherein separating directional components furtherincludes summing single trace data from sensors of said at least twosubstantially vertical arrays, in a manner such that elements of thesingle trace data being summed at any one time are located on anemerging wavefront of interest as a function of summing delays derivedfrom calibrated velocities, for producing a single trace data per sensorarray, per direction.
 31. The apparatus of claim 28, wherein separatingdirectional components includes coherency summing, coherency summingadapted to focus the at least two substantially vertical arrays ofsensors on a desired seismic scatterer by pattern recognition, furtherwherein a difference in direction of the desired seismic scatterer asviewed from the at least two substantially vertical arrays of sensors ismeasured as part of a triangulation process from at least two knownlocations, for establishing an apparent spatial position of the desiredseismic scatter.
 32. The apparatus of claim 28, wherein separatingdirectional components includes measurement of a dispersion velocitybetween a desired seismic scatterer and one of said at least twosubstantially vertical arrays of sensors by monofrequency decompositionof an apparent size and shape of Fresnel rings, the dispersion velocityadapted to correct the apparent spatial position of the desired seismicscatter.
 33. The apparatus of claim 26, wherein said processor isfurther for separating directional components, from a sum of thescattered seismic energy received from scatterers in substantially alldirections, by summing components along a desired direction defined byan azimuth and declination, between a distal sensor and a proximatesensor of said at least two substantially vertical arrays of sensors.34. The apparatus of claim 26, wherein said processor is further forsumming directional components of the recorded signals from successiveones of the sensors of said at least two substantially vertical arraysalong a wavefront traveling in a desired direction, the directiondefined by an azimuth and declination.
 35. The apparatus of claim 26,wherein said processor is further for processing the complete vectorfield for detecting and defining a type of particle motion with respectto a direction of an elastic wave propagation of seismic energy producedfrom a desired scatterer.
 36. The apparatus of claim 35, wherein thetype of particle motion includes longitudinal, vertically transversaland horizontally transversal waveforms.
 37. The apparatus of claim 35,wherein the type of particle motion includes other than longitudinal,vertically transversal and horizontally transversal waveforms.
 38. Amethod for surveying a three dimensional sub-surface geologicalstructure having seismic scatterers, the method comprising: establishingan acquisition system having at least two substantially vertical arraysof sensors disposed within the geological structure, wherein each arrayincludes multiple directional sensing receivers adapted to receiveseismic energy produced from the seismic scatterers in response to atleast one seismic disturbance, the multiple directional sensingreceivers further being adapted to provide a measurement of the receivedseismic energy; and recording the measurement of the received seismicenergy and producing a complete vector field response of the seismicscatterers to the at least one seismic disturbance.
 39. The method ofclaim 38, further comprising: positioning an omni-azimuthal source ofseismic energy proximate a surface of the geological structure forproviding the at least one seismic disturbance, the omni-azimuthalsource emitting a signal of sufficient energy and bandwidth to produceseismic energy from the seismic scatterers in response to the at leastone seismic disturbance, wherein recording the measurement furtherincludes recording the measurement of the seismic energy received by theat least two substantially vertical arrays of sensors in response to atleast one activation of the omni-azimuthal source.
 40. The method ofclaim 39, wherein the at least one seismic disturbance further includesone from a source other than the omni-azimuthal source of energy. 41.The method of claim 40, wherein the source other than the omni-azimuthalsource of energy includes physical changes in the sub-surface.
 42. Themethod of claim 40, wherein recording further includes recording atleast one omni-azimuthal signature, the omni-azimuthal signature beingadapted to correlate seismic energy received by the at least twosubstantially vertical arrays of sensors from seismic energy produced bythe seismic scatterer in response to the source other than theomni-azimuthal source of energy.
 43. The method of claim 40, furthercomprising: processing the complete vector field to generate athree-dimensional image.
 44. The method of claim 43, wherein recordingfurther includes recording the measurement of seismic energy of a firstcomplete vector field and a second complete vector field, the secondcomplete vector field representative of a time-lapsed first completevector field, and wherein processing further includes processing thefirst and second complete vector fields to identify a difference betweenthe first complete vector field and the second complete vector field,the difference being indicative of a sub-surface change within thegeological structure.
 45. The method of claim 43, wherein processingfurther includes separating directional components from a sum of thescattered seismic energy received from scatterers in substantially alldirections.
 46. The method of claim 45, wherein separating directionalcomponents includes summing signals of the complete vector field along adesired direction defined by an azimuth and declination, for producing asingle trace data per sensor, per direction.
 47. The method of claim 46,wherein separating directional components further includes summingsingle trace data from all sensors of said at least two substantiallyvertical arrays, in a manner such that elements of the single trace databeing summed at any one time are located on an emerging wavefront ofinterest as a function of summing delays derived from calibratedvelocities, for producing a single trace data per sensor array, perdirection.
 48. The method of claim 45, wherein separating directionalcomponents includes coherency summing, coherency summing adapted tofocus the at least two substantially vertical arrays of sensors on adesired seismic scatterer by pattern recognition, further wherein adifference in direction of the desired seismic scatterer as viewed fromthe at least two substantially vertical arrays of sensors is measured aspart of a triangulation process from at least two known locations, forestablishing an apparent spatial position of the desired seismicscatter.
 49. The method of claim 48, wherein separating directionalcomponents includes measurement of a dispersion velocity between adesired seismic scatterer and one of the at least two substantiallyvertical arrays of sensors by monofrequency decomposition of an apparentsize and shape of Fresnel rings, the dispersion velocity adapted tocorrect the apparent spatial position of the desired seismic scatter.50. The method of claim 41, wherein processing further includesseparating directional components, from a sum of the scattered seismicenergy received from scatterers in substantially all directions, bysumming components along a desired direction defined by an azimuth anddeclination, between a distal sensor and a proximate sensor of the atleast two substantially vertical arrays of sensors.
 51. The method ofclaim 41, wherein processing further includes summing directionalcomponents of the recorded signals from successive ones of the sensorsof the at least two substantially vertical arrays along a wavefronttraveling in a desired direction, the direction defined by an azimuthand declination.
 52. The method of claim 41, wherein processing furtherincludes processing the complete vector field for detecting and defininga type of particle motion with respect to a direction of an elastic wavepropagation of seismic energy produced from a desired scatterer.
 53. Themethod of claim 52, wherein the type of particle motion includeslongitudinal, vertically transversal and horizontally transversalwaveforms.
 54. The method of claim 52, wherein the type of particlemotion includes other than longitudinal, vertically transversal andhorizontally transversal waveforms.